System and process for recovering methane and carbon dioxide from biogas and reducing greenhouse gas emissions

ABSTRACT

Various illustrative embodiments of a system and process for recovering high-quality biomethane and carbon dioxide product streams from biogas sources and utilizing or sequestering the product streams are provided. The system and process synergistically yield a biomethane product which meets gas pipeline quality specifications and a carbon dioxide product of a quality and form that allows for its transport and sequestration or utilization and reduction in greenhouse gas emissions. The system and process result in improved access to gas pipelines for products, an improvement in the carbon intensity rating of the methane fuel, and improvements in generation of credits related to reductions in emissions of greenhouse gases.

RELATED APPLICATIONS

This application is a continuation application and claims the benefit,and priority benefit, of U.S. patent application Ser. No. 17/221,462,filed Apr. 2, 2021, which claims the benefit, and priority benefit, ofU.S. patent application Ser. No. 17/035,411, filed Sep. 28, 2020, nowU.S. Pat. No. 10,968,151, which claims the benefit, and prioritybenefit, of U.S. Provisional Patent Application Ser. No. 62/907,348,filed Sep. 27, 2019, the disclosure and contents of which areincorporated by reference herein in their entirety.

BACKGROUND Field of the Invention

The presently disclosed subject matter relates to recovery of biomethaneand carbon dioxide product streams from biogas sources.

Description of the Related Art

Biogas is gas produced through the decomposition of organic matter infacilities such as solid waste landfills, wastewater treatment plants,or other anaerobic digesters. Biogas is composed primarily of methaneand carbon dioxide, but also contains lesser amounts of other compounds.The gas is typically either flared to thermally destruct the combustiblecompounds or is beneficially utilized for its methane content. Typicalbeneficial use applications include combustion of the biogas forindustrial heating applications, combustion of the biogas forelectricity generation, or processing the biogas to generate a methane(biomethane) product that can be injected into natural gas pipelines orused in compressed natural gas (CNG) vehicle fuel applications. Thebeneficial use of biogas or biomethane typically leads to reductions ingreenhouse gas emissions due to the displacement of carbon dioxideemissions associated with the use and combustion of conventional fossilnatural gas. Regardless of whether the biogas is flared or beneficiallyutilized for the methane component, the carbon dioxide portion of thebiogas is ordinarily released to atmosphere. Capture and beneficialutilization, storage, or sequestration of the carbon dioxide portion ofthe biogas would lead to significant additional reductions in emissionsof greenhouse gases.

Municipal solid waste landfills are the largest generators and sourcesof biogas in the United States. Typical landfills in the United Statesproduce around 800-8,000 SCFM of biogas. The composition and rate ofproduction of the biogas is largely dependent on the fresh feed rate,existing volume, and composition of organic material; fresh feed rate,existing volume, and composition of other substances; operatingtemperature; moisture content; oxygen content; bacterial makeup; lengthof time spent digesting; and the design and operation of the digestionand gas extraction facilities. For example, the disposal of cosmeticsand deodorants within household waste leads to siloxanes in the biogas,the presence of refrigerants leads to halogenated hydrocarbons in thebiogas, and the operation of the landfill gas collection system undervacuum in an effort to limit fugitive emissions often incidentally leadsto the presence of nitrogen and oxygen in the biogas. While the primarycomponents of biogas are methane and carbon dioxide, the gas ordinarilyalso contains water vapor, nitrogen, and oxygen and can also containless than one percent of various other contaminants such as hydrogen,carbon monoxide, ammonia, sulfur compounds, halogenated hydrocarbons,siloxanes, other volatile and semi-volatile organic compounds, and heavymetals. While some measures can be taken to segregate certain wastes andadjust extraction rates from certain wells to control biogascomposition, the composition of biogas extracted from an active landfillvaries significantly over time.

Biogas beneficial use applications which involve processing the gas togenerate a biomethane product for injection into natural gas pipelinesrequire that the biomethane product be sufficiently purified fromcompounds that may jeopardize the integrity of pipeline systems, lead todamage of downstream equipment, or would pose risks to human orenvironmental health. Prospective biogas processing facilities whichwould include the recovery of carbon dioxide would similarly requirethat the recovered carbon dioxide be of suitable quality for transport,utilization, storage, or sequestration. As such, there is a need todesign advanced biogas processing facilities with sufficient robustnessto handle a wide range of potential inlet gas compositions andcontaminant levels while satisfying strict product purity requirements.Additionally, it is desirable that these processing facilities bedesigned to maximize the recovery of biomethane, maximize the recoveryof carbon dioxide, and minimize overall emissions of greenhouse gases.It is most desirable to do these things simultaneously andsynergistically.

Conventional methods of processing biogas for biomethane productioninvolve separation of methane and other compounds within the gas streamby passing the gas stream through various combinations of single-useadsorbent or scavenger beds, pressure-swing adsorption (PSA) packages,temperature-swing adsorption (TSA) packages, membranes, physicalsolvent-based absorbers, and chemical solvent-based absorbers. Theseconventional processes have certain limitations including limitations onmethane product purity and methane recovery rate. Despite the processingefforts, conventional methods can leave trace amounts of halogenatedhydrocarbons, other volatile organic compounds, siloxanes, oxygen,nitrogen, hydrogen, and heavy metals in the product gas. Additionally,less than about 97% of the inlet methane is typically recovered in theproduct gas. Further, the carbon dioxide portion of the biogas istypically separated in a gaseous state along with other contaminantswhich impairs and prevents subsequent transport, utilization, or storageof the carbon dioxide. Because the transport, utilization, or storage ofthe carbon dioxide portion of the biogas is impaired under conventionalprocessing techniques, reductions in overall emissions of greenhousegases are limited and the carbon intensity of the methane fuel istypically limited to around 30-60 gCO₂e/MJ. While previous patents haveattempted to present viable methods for recovering both biomethane andcarbon dioxide from biogas, these teachings have failed to present themost efficient methods for processing biogas to maximize recovery ofboth biomethane and carbon dioxide products of adequate quality and formto enable any subsequent use.

Improvements in this field of technology are desired.

SUMMARY

Various illustrative embodiments of a system and process for recoveringhigh-quality biomethane and carbon dioxide product streams from biogassources and utilizing or sequestering the product streams are disclosedherein. The system and process synergistically yield a biomethaneproduct which meets gas pipeline quality specifications and a carbondioxide product of a quality and form that allows for its transport andsequestration or utilization and reduction in greenhouse gas emissions.The system and process result in improved access to gas pipelines forproducts, an improvement in the carbon intensity rating of the methanefuel, and improvements in generation of credits related to reductions inemissions of greenhouse gases. Additionally, the system and process arean improvement to the overall methane recovery efficiency for biogasprocessing facilities. The system and process include low temperatureliquefaction of carbon dioxide from a biogas source to simultaneouslypurify the biomethane from contaminants and yield a marketable liquidcarbon dioxide product; sequestering or supplying the biogas-derivedcarbon dioxide for sequestration or other utilization; utilizing orsupplying the biomethane as compressed or liquefied fuel for vehicles,as process heat fuel, as feedstock for fuel or chemical synthesis, or asfeedstock for hydrogen generation; and monitoring the material andenergy inputs and outputs from the facility to verify reductions ingreenhouse gas emissions.

In certain illustrative embodiments, a process for recovering methaneand carbon dioxide from a biogas source for beneficial use orsequestration includes the steps of: (a) extracting at least one gasstream comprising a biogas from a biogas-generating facility; (b)compressing, cooling, and separating the gas stream from liquid water;(c) removing a majority of the trace contaminants from the gas stream;(d) removing oxygen from the gas stream to produce a deoxygenated gasstream; (e) drying the gas stream to reduce the water vapor content; (f)cooling the gas stream in a liquefaction unit to liquefy at least someof the contained carbon dioxide; (g) utilizing the liquid carbon dioxideas an absorbent to purify the gas stream; (h) separating any remaininggaseous carbon dioxide from the gas stream and recycling the gaseouscarbon dioxide to a point upstream from the liquefaction unit such thatthe carbon dioxide contained in the gas stream is substantiallyseparated and recovered as a liquid product; (i) separating nitrogenfrom the gas stream to produce a biomethane product stream; (j)sequestering or supplying the biogas-derived carbon dioxide product forsequestration or other utilization; (k) utilizing or supplying thebiomethane product stream as compressed or liquefied fuel for vehicles,as process heat fuel, as feedstock for fuel or chemical synthesis, or asfeedstock for hydrogen generation; and (l) monitoring the material andenergy inputs and outputs from a biogas processing facility to determinereductions in greenhouse gas emissions, wherein at least some of theaforementioned steps (b)-(i) occur in the biogas processing facility.Air intrusion into the biogas can be controlled to achieve a minimumoxygen to hydrogen, carbon monoxide, and hydrogen sulfide ratio of 0.5.The separated nitrogen stream can be utilized to regeneratecontaminant-laden adsorbent or absorbent. The contaminant-laden nitrogenstream can be transmitted to a thermal oxidizer or flare for thermaldestruction of the contaminants. The overall methane recovery efficiencycan be greater than 98%. The gross heating value of the biomethaneproduct can be greater than 1,000 Btu/SCF. The carbon intensity of thebiomethane can be less than 25 gCO₂e/MJ. The halogenated hydrocarbonlevel in the biomethane product stream can be less than 0.1 ppmv. Thesiloxane level in the biomethane product stream can be less than 0.01mgSi/m3. The carbon dioxide can be sequestered through injection into anunderground geologic reservoir. The reservoir can be monitored forverification of extended or permanent storage of carbon dioxide. Thecarbon dioxide can be sequestered through injection into an undergroundgeologic reservoir for enhancement of oil recovery. The reservoir can bemonitored for verification of extended or permanent storage of carbondioxide. The carbon dioxide can be sequestered through reaction withanother material to form carbonate minerals. The conversion of carbondioxide to carbonates can be monitored for verification ofsequestration. Credits can be generated due to the reduction ingreenhouse gases.

In certain illustrative embodiments, a process for recovering methaneand carbon dioxide from one or more biogas sources for beneficial use orsequestration includes the steps of: (a) extracting at least one gasstream comprising a biogas from a biogas-generating facility; (b)compressing, cooling, and separating the gas stream from liquid water;(c) removing a majority of the trace contaminants from the gas stream;(d) removing oxygen from the gas stream to produce a deoxygenated gasstream; (e) drying the gas to reduce the water vapor content; (f)cooling the gas stream in a liquefaction unit to liquefy at least someof the contained carbon dioxide; (g) utilizing the liquid carbon dioxideas an absorbent to purify the gas stream; (h) separating the remaininggaseous carbon dioxide from the gas stream to produce a biomethaneproduct stream and recycling the gaseous carbon dioxide to a pointupstream from the liquefaction unit such that the carbon dioxidecontained in the biogas is substantially separated and recovered as aliquid product; (i) sequestering or supplying the biogas-derived carbondioxide product for sequestration or other utilization; (j) utilizing orsupplying the biomethane product stream as compressed or liquefied fuelfor vehicles, as process heat fuel, as feedstock for fuel or chemicalsynthesis, or as feedstock for hydrogen generation; and (k) monitoringthe material and energy inputs and outputs from a biogas processingfacility to determine reductions in greenhouse gas emissions, wherein atleast some of the aforementioned steps (b)-(h) occur in the biogasprocessing facility. The overall methane recovery efficiency can begreater than 98%. The gross heating value of the biomethane product canbe greater than 1,000 Btu/SCF. The carbon intensity of the biomethanecan be less than 25 gCO₂e/MJ. The halogenated hydrocarbon level in thebiomethane product stream can be less than 0.1 ppmv. The siloxane levelin the biomethane product stream can be less than 0.01 mgSi/m3. Thecarbon dioxide can be sequestered through injection into an undergroundgeologic reservoir. The reservoir can be monitored for verification ofextended or permanent storage of carbon dioxide. The carbon dioxide canbe sequestered through injection into an underground geologic reservoirfor enhancement of oil recovery. The reservoir can be monitored forverification of extended or permanent storage of carbon dioxide. Thecarbon dioxide can be sequestered through reaction with another materialto form carbonate minerals. The conversion of carbon dioxide tocarbonates can be monitored for verification of sequestration. Creditscan be generated due to the reduction in greenhouse gases.

In certain illustrative embodiments, a process for recovering methaneand carbon dioxide from one or more biogas sources for beneficial use orsequestration includes the steps of: (a) extracting at least one gasstream comprising a biogas from a biogas-generating facility; (b)compressing, cooling, and separating the gas stream from liquid water;(c) removing a majority of the trace contaminants from the gas stream;(d) drying the gas stream to reduce the water vapor content; (e) coolingthe gas stream in a liquefaction unit to liquefy at least some of thecontained carbon dioxide; (f) utilizing the liquid carbon dioxide as anabsorbent to purify the gas stream; (g) separating the remaining gaseouscarbon dioxide from the gas stream to produce a biomethane productstream and recycling the gaseous carbon dioxide to a point upstream fromthe liquefaction unit such that the carbon dioxide contained in the gasstream is substantially separated and recovered as a liquid product; (h)sequestering or supplying the biogas-derived carbon dioxide liquidproduct for sequestration or other utilization; (i) utilizing orsupplying the biomethane product stream as compressed or liquefied fuelfor vehicles, as process heat fuel, as feedstock for fuel or chemicalsynthesis, or as feedstock for hydrogen generation; and (j) monitoringthe material and energy inputs and outputs from a biogas processingfacility to determine reductions in greenhouse gas emissions, wherein atleast some of the aforementioned steps (b)-(g) occur in the biogasprocessing facility. The overall methane recovery efficiency can begreater than 98%. The gross heating value of the biomethane product canbe greater than 1,000 Btu/SCF. The carbon intensity of the biomethanecan be less than 25 gCO₂e/MJ. The halogenated hydrocarbon level in thebiomethane product stream can be less than 0.1 ppmv. The siloxane levelin the biomethane product stream can be less than 0.01 mgSi/m3. Thecarbon dioxide can be sequestered through injection into an undergroundgeologic reservoir. The reservoir can be monitored for verification ofextended or permanent storage of carbon dioxide. The carbon dioxide canbe sequestered through injection into an underground geologic reservoirfor enhancement of oil recovery. The reservoir can be monitored forverification of extended or permanent storage of carbon dioxide. Thecarbon dioxide can be sequestered through reaction with another materialto form carbonate minerals. The conversion of carbon dioxide tocarbonates can be monitored for verification of sequestration. Creditscan be generated due to the reduction in greenhouse gases.

BRIEF DESCRIPTION OF THE DRAWINGS

A better understanding of the presently disclosed subject matter can beobtained when the following detailed description is considered inconjunction with the drawings and figures herein, wherein:

FIG. 1 is an example of a system and process for recovering biomethaneand carbon dioxide product streams from biogas sources and utilizing orsequestering the product streams in accordance with an illustrativeembodiment of the presently disclosed subject matter.

While the presently disclosed subject matter will be described inconnection with the preferred embodiment, it will be understood that itis not intended to limit the presently disclosed subject matter to thatembodiment. On the contrary, it is intended to cover all alternatives,modifications, and equivalents, as may be included within the spirit andthe scope of the presently disclosed subject matter as defined by theappended claims.

DETAILED DESCRIPTION

The presently disclosed subject matter relates to a system and processfor recovering high-quality biomethane and carbon dioxide productstreams from biogas sources and utilizing or sequestering the productstreams. The system and process improve upon conventional practices andyields a biomethane product which meets strict gas pipeline qualityspecifications and a carbon dioxide product of a quality and form thatallows for its sequestration or utilization and reduction in greenhousegas emissions. The system and process result in improved access to gaspipelines for products, an improvement in the carbon intensity rating ofthe biomethane fuel, and improvements in generation of carbon credits.Additionally, the system and process are an improvement to the overallmethane recovery efficiency for biogas processing facilities. In certainillustrative embodiments, the system and process can involve aspects of:extraction of one or more gas streams comprising biogas from abiogas-generating facility; compression, cooling, and separation ofliquid water; removal of a majority of the trace contaminants from thegas; removal of oxygen from the gas; drying the gas to further reducethe water vapor content; cooling the gas to liquefy at least some of thecontained carbon dioxide; utilizing the liquid carbon dioxide as anabsorbent to purify the gas stream; separating the remaining gaseouscarbon dioxide from the gas stream and recycling the gaseous carbondioxide to a point upstream from the liquefaction unit such that carbondioxide contained in the biogas stream is substantially separated as aliquid product; separating nitrogen from the gas stream; sequestering orsupplying the biogas-derived carbon dioxide for sequestration or otherutilization; utilizing or supplying the biomethane as compressed orliquefied fuel for vehicles, as process heat fuel, as feedstock for fuelor chemical synthesis, or as feedstock for hydrogen generation; andmonitoring the material and energy inputs and outputs from the biogasprocessing facility to verify reductions in greenhouse gas emissions. Asused herein, the phrase “biogas processing facility” shall not belimited to simply a single building, plant or other like facility, butshall also mean any collection of such buildings, plants or facilitiesas used to accomplish the subject matter described herein.

The majority of biomethane recovery processes for gas pipeline injectionapplications utilize PSA processes, membranes, or physical solvents, orsome combination thereof, but these processes and technologies haveshown certain limitations. While the purified biomethane product fromconventional processes may not consistently meet the most stringentspecifications for pipeline tariff gas quality parameters, the presentlydisclosed subject matter satisfies all known requirements (Tables 1 and2).

TABLE 1 Common gas quality parameters and modeled values based on anillustrative embodiment of this presently disclosed subject matter.Parameter An illustrative embodiment Gross Heating Value, BTU/SCF >1006Wobbe Number, BTU/SCF >1348 Hydrocarbon Dew Point, deg F. <−100 WaterVapor, lb/MMSCF <1 Total Sulfur, grains per 100 SCF <0.1 HydrogenSulfide, grains per 100 SCF <0.1 Diluents/Inerts, vol % <0.5 CarbonDioxide, vol % <0.002 Oxygen, vol % <0.001 Nitrogen, vol % <0.5

TABLE 2 Less common gas quality parameters and modeled values based onan illustrative embodiment of this presently disclosed subject matter.Parameter An illustrative embodiment Hydrogen, vol % <0.001 CarbonMonoxide, vol % <0.001 Siloxanes, mg Si/m3 <0.01 Halocarbons, ppmv <0.1Mercury, mg/m3 <0.01 Arsenic, mg/m3 <0.01 Antimony, mg/m3 <0.01 Copper,mg/m3 <0.01 Lead, mg/m3 <0.01 Other Volatile Metals, mg/m3 <0.01p-Dichlorobenzenes, mg/m3 <0.1 Ethylbenzene, mg/m3 <0.1n-Nitroso-di-n-propylamine, mg/m3 <0.01 Vinyl Chloride, mg/m3 <0.1Ammonia, vol % <0.001 Methacrolein, ppmv <0.1 Toluene, ppmv <0.1 AlkyThiols (mercaptans), ppmv <1 Semi-Volatile and Volatile Compounds, <0.1ppmv Aldehyde/Ketones, ppmv <0.1

The conventional PSA, membrane, and physical solvent-based approachesare also typically limited to methane recovery of less than 97% (Table3). Additionally, the conventional methods of biogas processing yield acontaminant-laden carbon dioxide off-gas at low pressure with littleapplicability, so the carbon dioxide is typically emitted to atmosphere.Due to the lack of carbon dioxide capture and sequestration orutilization, the biomethane product suffers from moderate carbonintensity ratings, typically in the range of 30-60 gCO₂e/MJ for bio-CNGapplications as compared to the baseline of about 100 gCO₂e/MJ forpetroleum-derived diesel or gasoline vehicle fuel (Table 4). Thepresently disclosed subject matter simultaneously and synergisticallyimproves upon these limitations and comprises a system and process whichensures that the biomethane product meets all pipeline gas qualityspecifications for any reasonable range of biogas feed conditions whilealso improving the methane recovery and carbon intensity rating for thebiomethane fuel due to capture and utilization or sequestration of thecarbon dioxide. By utilizing or sequestering the carbon dioxide andimproving the carbon intensity of the biomethane fuel, improved accessand value is gained in markets such as California and Oregon's LCFSmarkets, European markets, and the IRS 45Q tax credit for carbon oxidesequestration, which significantly improves revenue opportunity.

TABLE 3 Product recovery efficiencies for conventional processes versusan illustrative embodiment of the presently disclosed subject matter. Anillustrative Conventional biogas processing facilities embodiment Case 1Case 2 Case 3 Case 4 Case 5 Process description NMOC removal PSA,activated PSA, activated Selexol absorber Selexol absorber TSA, CO₂absorber carbon carbon CO₂ removal Membranes Membranes, Selexol absorberSelexol absorber, CO₂ liquefaction, amine absorber amine absorbermembranes, amine absorber O₂ removal Membranes, Membranes, O₂ converterO₂ converter O₂ converter PSA O₂ converter N₂ removal PSA Cryogenic PSACryogenic Cryogenic Product recovery CH₄ % 95.9 96.2 95.8 96.4 98.5 CO₂gCO₂/MJ 0.0 0.0 0.0 0.0 39.3

Conventional methods of biogas processing for methane recovery involveseparating and emitting the carbon dioxide contained in the biogas. Thispresently disclosed subject matter includes recovery of the carbondioxide for utilization or sequestration to substantially reduceemissions of carbon dioxide associated with the biomethane recoveryprocess and resultingly generate credits from the sequestration,utilization, and/or reduction in fuel carbon intensity. Process modelsand simulations were constructed using VMGSim with appropriatethermodynamic packages and equations of state to compare processefficiencies for conventional biogas processing facilities versus thepresently disclosed subject matter. For a baseline scenario where carbondioxide emissions from electricity generation are at the 2014 US averagelevels of 610 gCO₂e/kWh and the biomethane product is transported viapipeline 2,000 miles to a CNG fueling station, conventional landfillbiomethane recovery processes have carbon intensities of roughly 41-48gCO₂/MJ versus approximately 5 gCO₂e/MJ for the preferred embodiment(Table 4). At $100/ton CO₂ credit price, the equivalent credit or fuelpremium value for the baseline processes with carbon intensities of41-48 gCO₂e/MJ ranges from $3.9-4.6/mmbtu. Under the preferredembodiment with carbon intensity of approximately 5 gCO₂e/MJ, the creditor fuel premium values are equivalent to $8.3/mmbtu at $100/ton CO₂credit price, or approximately twice the value as credits fromconventional processes. For a moderate-scale 2,000 mmbtu/d biomethanefacility, the increase in revenue due to the improved credit or fuelpremium value results in an increase of approximately $3 million/year at$100/ton CO₂ credit price as compared to the conventional processes ofbiomethane recovery from biogas. Revenue may also be generated throughsale of the physical carbon dioxide product for use in enhanced oilrecovery or other industrial use which displaces use of geologicallystored carbon dioxide.

TABLE 4 Comparison of carbon intensities for conventional biomethanerecovery and utilization processes versus the preferred embodiment ofthe presently disclosed subject matter. An illustrative Conventionalbiogas processing facilities embodiment Carbon Intensity Case 1 Case 2Case 3 Case 4 Case 5 Base RNG process Feedstock processing Biogasextraction impact gCO2e/MJ 0.78 0.78 0.78 0.78 0.78 Grid electricityfactor gCO2e/kWh 610.34 610.34 610.34 610.34 610.34 Grid electricityimpact gCO2e/MJ 18.87 14.30 20.67 14.09 18.29 Natural gas factorgCO2e/mmbtu LHV 74,655 74,655 74,655 74,655 74,655 Natural gas impactgCO2e/MJ 3.93 4.56 4.99 5.43 0.99 Fugitive emissions factor Fraction0.01 0.01 0.01 0.01 0.01 Fugitive emissions impact gCO2e/MJ 4.61 4.594.66 4.59 4.52 Subtotal gCO2e/MJ 28.19 24.23 31.10 24.89 24.60 Gastransmission Distance miles 2,000 2,000 2,000 2,000 2,000 Pipelineemissions factor gCO2e/mmbtu-mile 4.08 4.08 4.08 4.08 4.08 Pipelineemissions impact gCO2e/MJ 6.98 6.98 6.98 6.98 6.98 Leakage factorgCO2e/mmbtu-mile 1.72 1.72 1.72 1.72 1.72 Leakage impact gCO2e/MJ 2.942.94 2.94 2.94 2.94 Subtotal gCO2e/MJ 9.93 9.93 9.93 9.93 9.93 CNG useCNG compression impact gCO2e/MJ 3.18 3.18 3.18 3.18 3.18 Tailpipeemissions impact gCO2e/MJ 3.66 3.66 3.66 3.66 3.66 Subtotal gCO2e/MJ6.84 6.84 6.84 6.84 6.84 Subtotal gCO2e/MJ 44.96 41.00 47.87 41.66 41.36CO2 recovery process CO2 capture CO2 emissions avoided gCO2/MJ N/A N/AN/A N/A 39 CO2 transport Distance miles N/A N/A N/A N/A 100 Trailercapacity Tonnes/trailer N/A N/A N/A N/A 19 Truck fuel efficiency milesper gallon N/A N/A N/A N/A 4.00 Fuel emissions factor gCO2e/gal N/A N/AN/A N/A 12,628 Fuel emissions impact gCO2e/MJ N/A N/A N/A N/A 1.31 CO2injection Pumping electric factor kWh/ton N/A N/A N/A N/A 2.00 Gridelectricity factor gCO2e/kWh N/A N/A N/A N/A 610.34 Grid electricityimpact gCO2e/MJ N/A N/A N/A N/A 0.05 Recovery fraction N/A N/A N/A N/A0.95 Subtotal gCO2e/MJ N/A N/A N/A N/A −36.06 Total gCO2e/MJ 44.96 41.0047.87 41.66 5.31

Conventional methods of biomethane recovery from biogas can leave traceamounts of halogenated compounds and siloxanes with the methane streamwhich can limit injection into pipelines due to pipeline qualitystandards. The presently disclosed subject matter involves removal ofsiloxanes to less than 0.01 mg Si/m3 and removal of halogenatedcompounds to less than 0.1 ppmv, meeting any current pipelinespecification (Tables 1 and 2). Conventional methods of methane recoveryfrom biogas can leave minor amounts of carbon dioxide and nitrogen withthe methane stream which can limit injection into pipelines due topipeline quality standards for inert gases or heating value. Thepreferred embodiment removes carbon dioxide and nitrogen to less than0.5% in the methane gas and achieves a GHV of greater than 1,000Btu/SCF, meeting all US pipeline gas quality specifications for carbondioxide, nitrogen, total inert gases, heating value, and Wobbe Number(Table 1). Conventional methods of methane recovery from biogas canleave minor amounts of oxygen, hydrogen, and carbon monoxide with themethane stream which can limit injection into pipelines due to pipelinequality standards for oxygen, hydrogen, or carbon monoxide. Thepreferred embodiments involve removing all oxygen, hydrogen, and carbonmonoxide, meeting all known pipeline specifications for oxygen,hydrogen, and carbon monoxide (Tables 1 and 2).

An illustrative embodiment of the presently disclosed system and process10 is shown in FIG. 1 . FIG. 1 illustrates an exemplary system andprocess 10 with a plurality of sequential, non-sequential, or sequenceindependent “steps” using the equipment shown or described herein. Itshould be noted that the system and process 10 of FIG. 1 is exemplary,and may be performed in different orders and/or sequences as dictated orpermitted by the equipment described herein, and any alternativeembodiments thereof. Other arrangements of the various “steps” andequipment can be utilized. In addition, not all “steps” or equipmentdescribed herein need be utilized in all embodiments. However, it shouldbe noted that certain particular arrangements of equipment and/or“steps” for the system and process 10 such as shown in FIG. 1 arepreferred embodiments, and are materially distinguishable from andprovide distinct advantages over previously known technologies.

Extraction of Biogas

In certain illustrative embodiments, biogas is extracted from a biogasgenerating facility through conventional methods. If the biogasgenerating facility is a solid waste landfill, the biogas is extractedvia a blower which pulls a slight vacuum on a gas collection system. Ifhydrogen sulfide, hydrogen and/or carbon monoxide are contained in thebiogas, oxygen can be drawn in from atmosphere along with the biogas ata ratio of at least 0.5 moles oxygen to moles hydrogen sulfide,hydrogen, and carbon monoxide to facilitate removal of hydrogen sulfide,hydrogen, and carbon monoxide downstream.

Compression, Cooling, and Separation of Water

In certain illustrative embodiments, biogas is compressed, cooled, andseparated from liquid water using conventional methods. In the preferredembodiment, biogas is compressed to about 5-15 psig, cooled in anair-cooled heat exchanger to around ambient dry bulb temperature or in awater-cooled heat exchanger to around ambient wet bulb temperature, andseparated from liquid water.

Removal of the Majority of the Trace Contaminants and Oxygen

In certain illustrative embodiments, hydrogen sulfide is removed fromthe biogas using conventional means such as through adsorption onactivated carbon, reaction with iron oxide based media, or absorption ina wet scrubber. The hydrogen sulfide may also be removed from the biogasvia less conventional means, such as through oxidation to sulfur dioxideand wet scrubbing of the sulfur dioxide. Depending on the method ofremoving hydrogen sulfide, the humidity, temperature, and oxygen levelin the feed gas are controlled to provide optimal conditions for thehydrogen sulfide removal process. For example, for hydrogen sulfideremoval on specialized activated carbon or iron oxide media, the oxygenlevel should be controlled to at least 0.5 moles oxygen per molehydrogen sulfide to facilitate conversion to elemental sulfur. Forhydrogen sulfide removal through oxidation to sulfur dioxide, the oxygenin the feed should be controlled to at least 1.5 moles oxygen per molehydrogen sulfide.

In certain illustrative embodiments, following removal of hydrogensulfide, the biogas is compressed to about 90-150 psig, cooled in amanner similar to the first stage, and separated from any liquid. Thebiogas is compressed further to between about 250-700 psig, cooled in amanner similar to the first stage, and separated from any condensedliquid. In certain illustrative embodiments, the compressed biogas isseparated from the bulk of the minor contaminants, including organicsulfides, halogenated hydrocarbons, siloxanes, semi-volatile andvolatile organic compounds, and volatile metals using a PSA or TSAprocess. The majority of the contaminants may alternatively be removedvia a physical solvent absorber, but the preferred approach is a TSA.The adsorbents consist of media with known affinity for adsorption ofthe majority of landfill gas contaminants, such as activated carbon,promoted activated carbon, silica gel, molecular sieves, or somecombination. The spent beds are regenerated by flowing nitrogen that hasbeen separated from the gas through the spent bed at a pressure lowerthan adsorption pressure and, preferably, higher than adsorptiontemperature. Preferably, the nitrogen flows through the bed at apressure between 1-10 psig and at a temperature between 300-800 deg F.and is then routed to a thermal oxidizer or flare for thermaldestruction of the separated contaminants. A single vessel or lead-lagarrangement of promoted or unpromoted activated carbon bed may be placeddownstream from the PSA or TSA to help polish the gas.

The physical adsorbents are efficient at removing the bulk of thecontaminants, particularly contaminants with relatively high boilingpoints. However, low boiling compounds, including some halogenatedhydrocarbons, have very low adsorption tendencies and are not typicallycompletely removed. Chloromethane for example, has very minimal loadingon activated carbon. Therefore, in order to avoid extremely large andcostly physical adsorbent systems, it is advantageous to allow the mostdifficult to adsorb contaminants, such as low boiling halogenatedhydrocarbons, to pass through the physical adsorbents and instead removethem downstream in the carbon dioxide liquefaction process.

In certain illustrative embodiments, following removal of the bulk ofthe minor contaminants through adsorption, the gas may be transmitted toa catalytic oxidation reactor. The catalytic oxidation reactor mayalternatively be placed in a variety of different locations in theprocess, but, in the preferred embodiment, the reactor is placeddownstream from the bulk contaminant removal by adsorption to minimizepoisoning and prolong the lifetime of the oxidation catalyst. Thereactor utilizes platinum group metal catalysts to catalyze theoxidation of hydrogen, carbon monoxide, and residual reactive VOC's tosimultaneously remove the hydrogen, carbon monoxide, VOC's, and oxygen.The oxygen level in the feed gas can be maintained at minimum of 0.5moles oxygen to moles hydrogen and carbon monoxide by controlling thevacuum or air intrusion into the biogas. If necessary, an easilyreactive chemical, such as methanol, can be injected into the feedstream to facilitate and complete the removal of oxygen. The catalyticoxidation reactor preferably operates at a temperature less than 575 degF. Alternatively, the reactor may be operated at temperatures greaterthan 575 deg F. to facilitate removal of oxygen by oxidation of methane,but this is less desirable.

Drying the Gas Stream

In certain illustrative embodiments, the gas stream is then dried usingconvention technology, such as molecular sieve, silica gel, ortriethylene glycol dryer. In the preferred embodiment, the gas is driedwith a molecular sieve drier to a moisture dew point temperature of lessthan −40 deg F., and the spent beds are regenerated by flowing a portionof the dried gas back through the spent bed at an elevated temperaturebetween about 300-500 deg F. The regeneration steam is cooled andrecycled to a point upstream the previous compression stage.

Carbon Dioxide Liquefaction and Utilization as an Absorbent to Purifythe Gas Stream

Following drying, in certain illustrative embodiments the gas is cooledto liquefy a portion of the contained carbon dioxide such that carbondioxide may be separated from the gas stream as a liquid. In thepreferred embodiment, the dried gas is first pre-cooled to less than 50deg F. before being fed to refluxed absorber column. The overhead gasstream from the column is transmitted to a cooler or condenser where thegas is cooled to a point where a portion of the contained carbon dioxidecondenses as liquid. Preferably, the gas is cooled to a temperaturebetween −25 and −75 deg F. The gas and the liquid carbon dioxide streamare separated, and the liquid carbon dioxide is transmitted back to theupper section absorber column as reflux. As the liquid carbon dioxidetravels down the column, the liquid carbon dioxide absorbs contaminantsfrom the feed stream. As result, the overhead gas stream is purifiedfrom contaminants (Table 5). The bottoms product stream is primarilycomposed of liquid carbon dioxide as well as a small amount of methaneand any absorbed contaminants that had passed through the upstream bulkcontaminant removal process. In the preferred embodiment, the pressureof the bottom product stream is reduced such that a portion of thestream is vaporized, including most of the methane that was contained inthe liquid carbon dioxide stream. The methane-rich vapor is thenrecycled to a point upstream the previous compression stage.

As an alternative to using of an absorber tower, the gas stream maysimply be cooled to the point at which carbon dioxide condenses asliquid which is then separated from the vapor stream in a two-phaseseparator. However, the potential for reduction of contaminant levels inthe gas stream is reduced in this embodiment. The method which involvesan absorber column has the advantages of ensuring a purified gas streamis produced as well as the advantage that the feed gas warms the liquidcarbon dioxide as the two streams become in contact, which allows forimmediate flashing of the bottoms stream for methane recovery andrecycle.

TABLE 5 Fate of representative contaminants fed to the carbon dioxideliquefaction and absorber unit at inlet concentration of 1 ppmv.Contaminant Molecular Concentration in Contaminant in Contaminant inweight feed gas biomethane product carbon dioxide product Halogenatedmethanes g/mol mol frac mol frac % removed mol frac % absorbedChloromethane 50.49 1.0E+00 1.0E−100 100 2.5E−06 100 Dichloromethane84.93 1.0E−06 1.0E−100 100 2.5E−06 100 Trichloromethane 119.38 1.0E−061.0E−100 100 2.5E−06 100 Tetrachloromethane 153.82 1.0E−06 1.0E−100 1002.5E−06 100 Chlorofluoromethane 68.48 1.0E−06 1.0E−100 100 2.5E−06 100Chlorodifluoromethane 86.47 1.0E−06 6.4E−13  100 2.5E−06 100Dichlorofluoromethane 102.92 1.0E−06 1.0E−100 100 2.5E−06 100Dichlorodifluoromethane 120.91 1.0E−06 1.1E−11  100 2.5E−06 100Trichlorofluoromethane 137.37 1.0E−06 1.0E−100 100 2.5E−06 100

Separating the Remaining Gaseous Carbon Dioxide from the Gas Stream

In certain illustrative embodiments, the purified gas stream is sent toadditional separation equipment to separate the remaining gaseous carbondioxide from the gas stream. The carbon dioxide may be separated fromthe gas using conventional methods, such as through PSA, membranes, useof physical solvents, use of chemical solvents, or some combination. Inthe preferred embodiment, the enriched biomethane from the liquefactionunit is sent to a membrane package, which reduces the carbon dioxidelevel to less than about 5 percent, then to an amine absorber to polishthe carbon dioxide level to less than about 50 ppm. The permeate fromthe membrane is recycled to a point upstream from the previouscompression stage. The rich amine solution from the amine absorber isflashed and sent to a regenerator tower to separate the carbon dioxidefrom the amine solution and allow recycle of the carbon dioxide to apoint upstream from the previous compression stage. As a result, thecarbon dioxide contained in the biogas is substantially separated andrecovered as a liquid product.

Separating Nitrogen from the Biogas

In certain illustrative embodiments, the gas stream which has beenseparated from carbon dioxide is further dried and sent to a nitrogenremoval unit for separation of nitrogen using conventional technology.The nitrogen removal unit may be composed of membranes, a PSA whichpreferentially adsorbs methane, a PSA which preferentially adsorbsnitrogen, or a cryogenic separation unit. In the preferred embodiment,the nitrogen is separated in a single or double column cryogenicseparation process. If necessary, the pressure of the gas stream isfirst boosted via compression, then the gas is pre-cooled and let downin pressure via a Joule-Thomson valve to cool the gas to the point atwhich a portion of the methane is condensed as liquid and then fed to acryogenic distillation column. Liquefied methane is withdrawn as abottom stream from the column, and enriched nitrogen is withdrawn as anoverhead vapor stream. The overhead nitrogen-rich vapor stream is cooledfurther and let down in pressure via another Joule-Thomson valve to coolfurther and condense a portion of the stream. The stream is then fed toa reboiled absorber column which further separates the nitrogen andmethane such that the overhead stream consists primarily of nitrogenwith less than one percent methane, and the bottoms stream consistsprimarily of liquified methane stream.

In the preferred embodiment, the overhead nitrogen stream is heated andsent to the TSA where the bulk of the contaminants are desorbed from aspent bed into the nitrogen stream and routed to a thermal oxidizer orflare for thermal destruction of the contaminants. The liquifiedbiomethane streams are heated, combined, and recompressed to desireddelivery pressure from the biogas processing facility. In the preferredembodiment, the heating and cooling requirements of the cryogenicnitrogen removal process are combined such that no externalrefrigeration is required. However, for liquefied natural gas (LNG)applications, external refrigeration may be used and the liquefiedbiomethane may be left in liquid form and pumped to desired deliverypressure. The biomethane product stream from the nitrogen removal unitcontains less than 0.5% nitrogen and contains greater than 98% of themethane delivered to the biogas processing facility.

Thermal Oxidation or Flaring of Waste Gases

In certain illustrative embodiments, the separated nitrogen stream issent to the TSA to regenerate an adsorbent bed which is saturated withcontaminants. The contaminants are desorbed from the saturated bed intothe nitrogen stream and routed to a thermal oxidizer, regenerativethermal oxidizer, or flare for thermal destruction of the contaminants.If a physical solvent is alternatively used for bulk contaminantremoval, the nitrogen may be used to strip the solvent from contaminantsand routed to the thermal oxidizer or flare for thermal destruction ofthe contaminants. The presently disclosed subject matter results in areduced fuel load on the thermal oxidizer due primarily to the fact thatthe carbon dioxide is not routed to the thermal oxidizer. This not onlyresults in fuel gas savings, but an improved carbon intensity rating forthe biomethane fuel and improved generation of credits.

Sequestering or Utilizing the Carbon Dioxide

In certain illustrative embodiments, the carbon dioxide separated fromthe biogas is sequestered or utilized in a manner which isolates ordisplaces emissions of carbon dioxide. The carbon dioxide may besequestered through use in enhanced oil recovery, injected into securegeologic formations, injected into deep marine sediments, or reactedwith certain rocks and minerals to form stable carbonates. The carbondioxide may alternatively be utilized as feedstock in chemical or fuelsynthesis, as an industrial refrigerant, or in the food and beverageindustry in a manner which avoids extraction of geologic carbon dioxideand reduces emissions. The sequestration or utilization may occur onsite, or the carbon dioxide may be supplied to another party andtransported via truck, rail, barge or pipeline to another facility forsequestration or utilization. The carbon dioxide may be pumped to reachrequired delivery pressure and heated as needed to meet particulartemperature requirements for transport, sequestration, or utilization.In the preferred embodiment, the carbon dioxide is supplied to anotherparty and transported via truck or pipeline to another facility to beinjected underground into a suitable geologic formation for permanentstorage.

Utilizing the Biomethane

In certain illustrative embodiments, the biomethane product is utilizedas compressed or liquefied fuel for vehicles, as feedstock for synthesisof chemicals or fuels, or as process heat fuel. The gas may be utilizedon site or sold and transported via pipeline, truck, barge, or rail toan off-site CNG or LNG fueling station for use as a vehicle fuel or toanother facility for use as process heat fuel. The biomethane may alsobe used as feedstock in a fuels or chemicals synthesis facility togenerate renewable diesel, renewable gasoline, biomethanol, orbioethanol. The biomethane may also be reformed to generate hydrogen foruse in petroleum refining or in vehicle fuel applications.

Monitoring Feedstock Usage, Production, and Emissions

In certain illustrative embodiments, the material and energy inputs andoutputs from the facility are monitored to verify reductions inemissions of greenhouse gases associated with the biogas processing. Theflow rate and composition of the biogas feedstock is monitored, as wellas any process heat fuel usage and electricity usage. The production andcomposition of the biomethane and carbon dioxide products are monitored,and the off-gas to the thermal oxidizer or flare may be monitored aswell to close the material and energy balance and verify reductions inemissions of greenhouse gases.

In accordance with the presently disclosed subject matter, when there isa desire or need for high pressure carbon dioxide, such as when carbondioxide is transported via pipeline or injected underground for inenhanced oil recovery or geologic storage, it is most efficient toseparate carbon dioxide via low temperature fractionation orliquefaction as opposed to conventional means of separation due to thefact that much less power is required to pump liquid carbon dioxide upto delivery pressure than is required to compress gaseous carbon dioxideup to required delivery pressure. Similarly, when there is a need forliquid carbon dioxide, such as when transported via truck, rail, orbarge, it is most efficient to separate the carbon dioxide as a liquidvia low temperature fractionation or liquefaction. The presentlydisclosed system and process allow for separation of the carbon dioxidefrom the biogas in a relatively pure liquid form which is suitable fortransport, utilization, or storage and enable significant reductions inoverall greenhouse gas emissions and improvements in generation ofassociated credits. Accomplishing this feat while simultaneously andsynergistically generating a purified biomethane product and improvingthe overall methane recovery efficiency of the process results in asignificant improvement beyond current practices.

While the disclosed subject matter has been described in detail inconnection with a number of embodiments, it is not limited to suchdisclosed embodiments. Rather, the disclosed subject matter can bemodified to incorporate any number of variations, alterations,substitutions or equivalent arrangements not heretofore described, butwhich are commensurate with the scope of the disclosed subject matter.

Additionally, while various embodiments of the disclosed subject matterhave been described, it is to be understood that aspects of thedisclosed subject matter may include only some of the describedembodiments. Accordingly, the disclosed subject matter is not to be seenas limited by the foregoing description, but is only limited by thescope of the claims.

What is claimed is:
 1. A process for recovering carbon dioxide from abiogas source, comprising the steps of: (a) extracting at least one gasstream comprising a biogas from a biogas-generating facility; (b)compressing, cooling, and separating the gas stream from liquid water;(c) removing a majority of trace contaminants from the gas stream; (d)cooling the gas stream in a liquefaction unit to liquefy at least someof the contained carbon dioxide; (e) separating remaining gaseous carbondioxide from the gas stream and recycling the gaseous carbon dioxide toa point upstream from the liquefaction unit such that the carbon dioxideis substantially recovered as a liquid product; and (f) monitoringmaterial and energy inputs and outputs from a biogas processingfacility, wherein at least some of steps (b)-(e) occur in the biogasprocessing facility.
 2. The process of claim 1, including any of theadditional steps of: (a) removing oxygen from the gas stream to producea deoxygenated gas stream; (b) drying the gas stream to reduce the watervapor content; (c) utilizing the liquified carbon dioxide as anabsorbent to purify the gas stream; (d) separating nitrogen from the gasstream; (e) sequestering or supplying the carbon dioxide product forsequestration or other utilization; or (f) utilizing or supplying abiomethane product stream produced from the gas stream as a compressedor liquefied fuel for vehicles, as process heat fuel, as feedstock forfuel or chemical synthesis, or as feedstock for hydrogen generation.